Hydrocarbons such as oil, natural gas, etc. are obtained from a subterranean geologic formation (e.g. a “reservoir”) by drilling a well that penetrates the hydrocarbon-bearing formation. This provides a partial flowpath for the hydrocarbon, typically oil, to reach the surface. In order for oil to be “produced”, that is, travel from the formation to the wellbore (and ultimately to the surface), there must be a sufficiently unimpeded flowpath through the formation rock (e.g. sandstone, carbonates), which generally occurs when rock pores of sufficient size and number are present.
In the recovery of hydrocarbons, such as oil and gas, from natural hydrocarbon reservoirs, extensive use is made of wellbore treatment fluids such as drilling fluids, completion fluids, workover fluids, packer fluids, fracturing fluids, conformance or permeability control fluids and the like.
Generally, techniques used to increase the permeability of the formation are referred to as “stimulation”. Stimulation of the formation can be performed by: (1) injecting chemicals into the wellbore to react with and/or dissolve damage; (2) injecting chemicals through the wellbore and into the formation to react with and/or dissolve small portions of the formation to create alternative flowpaths for the hydrocarbon; or (3) injecting chemicals through the wellbore and into the formation at pressures sufficient to fracture the formation, thereby creating a channel through which hydrocarbon can more readily flow from the formation and into the wellbore.
Hydraulic fracturing involves breaking or fracturing a portion of the surrounding strata of the formation, by injecting a specialised fluid into the wellbore directed at the face of the formation at pressures sufficient to initiate and extend a fracture in the formation. Typically, the process creates a fracture zone, that is, a zone in the formation having multiple fractures, through which hydrocarbon can more easily flow to the wellbore.
In many cases significant components of fracturing fluids and other wellbore fluids are thickening agents, usually based on polymers or viscoelastic surfactants, which serve to control the viscosity of the fluids. Typical viscoelastic surfactants are N-erucyl-N,N-bis(2-hydroxyethyl)-N-methyl ammonium chloride and potassium oleate, solutions of which form gels when mixed with inorganic salts such as potassium chloride and/or with organic salts such as sodium salicylate.
Conventional surfactants, specifically those which tend to form spherical micelles, are generally not capable of forming a viscoelastic composition, particularly an aqueous viscoelastic composition, and are thus not suitable for use in a hydraulic fracturing application. However, certain surfactants, specifically those which tend to form long rod-like or worm-like micelle structures, e.g. viscoelastic surfactants, are capable of forming an aqueous viscoelastic composition. At a relatively low total concentration of a viscoelastic surfactant, typically in the range 1 to 10 wt %, these long rod-like or worm-like micelle structures overlap, forming an entangled network which is viscoelastic. Typically, these large micelle structures are readily destroyed by their interaction with formation fluids such as hydrocarbon fluids. When the micellar structures are broken by their interaction with the hydrocarbon fluid, a solution with low viscosity is formed. If a viscoelastic surfactant based fracturing fluid interacts with produced hydrocarbon fluids, a dramatic change in micellar structure (from rod-like or worm-like to spherical micelles) for instance causes a dramatic change in the rheological properties of the fracturing fluid (from a viscoelastic composition to an inviscid solution). It is this “responsive” fluid which facilitates easy removal and clean up of the fluid from the propped fracture so as to maximise hydrocarbon production.
The application of viscoelastic surfactants in both non-foamed and foamed fluids used for fracturing subterranean formations has been described in several patents, e.g. EP-A-0835983, U.S. Pat. Nos. 5,258,137, 5,551,516, 5,964,295 and 5,979,557.
The use of viscoelastic surfactants for water shut off treatments and for selective acidizing is discussed in GB-A-2332224 and Chang F. F., Love T., Affeld C. J., Blevins J. B., Thomas R. L. and Fu D. K., “Case study of a novel acid diversion technique in carbonate reservoirs”, Society of Petroleum Engineers, 56529, (1999).
The use of amide sulphonates in oilfield applications is also known. For example, N-acyl N-methyl taurates have been used as foaming agents in foam drilling and workover applications (U.S. Pat. No. 3,995,705) and as scale inhibitors in acidising formulations (U.S. Pat. Nos. 3,924,685, 3,921,718 and U.S. Pat. No. 3,921,716). Of these, for example, U.S. Pat. No. 3,924,685 describes a method of increasing and sustaining production of fluids from a subterranean fluid-bearing formation by injecting an aqueous solution containing a water-soluble substituted taurine, such as N-oleoyl N-methyl taurate, sodium N-palmitoyl N-methyl taurate or sodium N-acyl N-methyl taurate. This patent does not, however, (i) demonstrate that such water-soluble substituted taurine compounds can form viscoelastic gels or (ii) describe any methods to cause an increase in the viscosity of the fluid. Thus, although amide sulphonates have found use as surfactants in a variety of oilfield applications, they have not been used in the preparation of viscoelastic surfactant gels.